1. Field of the Invention
The present invention pertains to centralizers used during operations in oil and/or gas wells. More particularly, the present invention pertains to bow-type centralizers used to centralize casing strings or other tubular goods within said wellbores.
2. Brief Description of the Prior Art
Drilling of an oil or gas well is frequently accomplished using a surface drilling rig and tubular drill pipe. When installing drill pipe (or other tubular goods) into a wellbore, such pipe is typically inserted into said wellbore in a number of sections of roughly equal length commonly referred to as “joints”. As a wellbore penetrates deeper into the earth, additional joints of pipe must be added to an ever lengthening “drill string” at the drilling rig in order to increase the length of said drill string.
After a wellbore is drilled to a desired depth, relatively large diameter pipe known as casing is typically installed within said wellbore and then cemented in place. When casing is installed into a wellbore, a desired length of casing is typically formed by joining together a number of individual joints or sections of roughly equal length to form a continuous string; an individual joint is threadedly connected to the upper end of the then-existing casing string at a drilling rig, the string is then lowered a desired distance into a wellbore, and the process is repeated until a casing string has a desired overall length.
As casing is installed in a wellbore, it is frequently beneficial to rotate and/or reciprocate such casing within said wellbore. After the casing is installed, cementing is performed by pumping a predetermined volume of cement slurry into the well using high-pressure pumps. The cement slurry is typically pumped down the central through bore of the casing, out the bottom or distal end of the casing, and around the outer surface of the casing.
After a predetermined volume of cement is pumped, a plug or wiper assembly is typically pumped down the inner bore of the casing using drilling mud or other fluid in order to fully displace the cement from the inner bore of the casing. In this manner, cement slurry leaves the inner bore of the casing and enters the annular space existing between the outer surface of the casing and the inner surface of the wellbore. After such cement hardens, it should beneficially secure the casing in place and form a fluid seal to prevent fluid flow along the outer surface of the casing.
In many conventional cementing operations, devices known as “centralizers” are frequently used in connection with the installation and cementing of casing in wells. Such centralizers are often “subs” that are threadedly included within a casing string in order to center such casing string within a wellbore in order to obtain a uniformly thick cement sheath around the outer surface of the casing. Different types of centralizers have been used, and casing centralization is generally well known to those having skill in the art. Centralization of a casing string near its bottom end, in particular, is frequently considered especially important to securing a uniform cement sheath and, consequently, a fluid seal around the bottom (distal) end of a casing string. For that reason, placement of centralizer subs at or near the distal end of a casing string is often desirable.
One common type of centralizer is a “bow spring” centralizer sub. Such bow spring centralizer subs typically comprise a pair of spaced-apart end bands which encircle a central tubular member that can be installed within the length of a casing string, and are held in place at a desired location on the casing. A number of outwardly bowed, resilient bow spring blade members connect the two end bands, spaced at desired locations around the circumference of said bands. The configuration of bow spring centralizers permits the bow spring blades to at least partially collapse as a casing string is run into a borehole and passes through any diameter restriction, such as a piece of equipment or wellbore section having an inner diameter smaller than the extended bow spring diameter. Such bow springs can then extend back radially outward after passage of said centralizer sub through said reduced diameter section.
Unlike conventional land or platform-based drilling operations, when drilling is conducted from drill ship rigs, semi-submersible rigs and certain jack-up rigs, subsea blowout preventer and wellhead assemblies are located on or in the vicinity of the sea floor. Typically, a large diameter pipe known as a riser is used as a conduit to connect the subsea assemblies to such rig. During drilling operations, drill pipe and other downhole equipment are lowered from a rig through such riser, as well as through the subsea blowout preventer assembly and wellhead, and into the hole which is being drilled into the earth's crust.
When a casing string is installed in such a well, the upper or proximate end of such casing string is typically seated or “landed” within a subsea wellhead assembly. In such cases, it is generally advantageous that a fluid pressure seal be formed between the casing string and the wellhead assembly. In order to facilitate such a seal, certain internal surface(s) of the subsea wellhead often include at least one polished bore receptacle or elastomer/composite sealing element which is designed to receive and form a fluid pressure seal with the casing string. As a result, the internal sealing surface of the wellhead assembly, and particularly such polished bore receptacle(s) and/or sealing elements, must be clean and relatively free from wear so that a casing string can be properly seated and sealed within the wellhead.
The running of pipe (drill string, casing and/or other equipment) through a wellhead can cause wear on the internal surface of a wellhead, thereby damaging the inner sealing profile of said wellhead and making it difficult for casing to be properly received within said wellhead. This is especially true for items having a larger outer diameter than other pipe or tubular goods passing through a wellhead (such as, for example centralizers), as such larger items have a tendency to gouge, mar, scar and/or scratch polished surfaces or sealing areas of said wellhead.
In certain circumstances, it is beneficial for components of a centralizer assembly (that is, end bands and bow springs) and said central tubular member (which is threadedly attached to the larger casing string) to be capable of rotating relative to one another. In other words, in certain circumstances (particularly when a casing string is being rotated) it is beneficial for said central tubular member to rotate within said centralizer assembly. However, when conventional centralizer bow springs are compressed—such as during passage of a centralizer assembly through restrictions in a well or other equipment—said bow springs can come in contact with and “pinch” against the outer surface of said central tubular member. Such contact generates frictional resistance forces that prevent a central tubular member from freely rotating within such centralizer components (end bands and bow springs). Conventional rotating centralizer designs cause high rotating torques due to such frictional resistance forces encountered during pipe rotation operations.
Thus, there is a need for a relatively low cost bow-spring type centralizer assembly having a low profile when in a collapsed configuration (such as when passing through a wellbore restriction), and improved rotating capability creating less frictional resistance during rotation. Said bow-spring centralizer assembly should exhibit superior strength characteristics, while minimizing damage to wellheads, polished bores or other downhole equipment.